U.S. patent number 4,609,539 [Application Number 06/640,679] was granted by the patent office on 1986-09-02 for process for simultaneously removing sulfur oxides and particulates.
This patent grant is currently assigned to Standard Oil Company (Indiana). Invention is credited to Eugene H. Hirschberg, Carl J. Horecky.
United States Patent |
4,609,539 |
Horecky , et al. |
September 2, 1986 |
**Please see images for:
( Certificate of Correction ) ** |
Process for simultaneously removing sulfur oxides and
particulates
Abstract
A process is provided in which particulates and sulfur oxides
are simultaneously removed from flue gases in a granular bed filter
and scrubber with special sulfur oxide-capturing and
particulate-removing material. The spent sulfur oxide-capturing and
particulate-removing material can be regenerated in a lift pipe
riser.
Inventors: |
Horecky; Carl J. (Elmhurst,
IL), Hirschberg; Eugene H. (Park Forest, IL) |
Assignee: |
Standard Oil Company (Indiana)
(Chicago, IL)
|
Family
ID: |
24569268 |
Appl.
No.: |
06/640,679 |
Filed: |
August 13, 1984 |
Current U.S.
Class: |
423/244.09;
208/113; 208/120.01; 208/120.05; 208/120.1; 208/120.2; 423/239.1;
423/563; 423/567.1; 423/574.1; 95/110; 95/135; 95/137 |
Current CPC
Class: |
B01D
53/08 (20130101); B01D 53/508 (20130101); B01D
2259/402 (20130101); B01D 2251/202 (20130101); B01D
2251/204 (20130101); B01D 2251/2062 (20130101); B01D
2251/208 (20130101); B01D 2251/40 (20130101); B01D
2251/602 (20130101); B01D 2253/104 (20130101); B01D
2253/106 (20130101); B01D 2253/1124 (20130101); B01D
2253/25 (20130101); B01D 2257/302 (20130101); B01D
2257/404 (20130101); B01D 2258/0283 (20130101); B01D
2259/40081 (20130101); B01D 2259/40086 (20130101) |
Current International
Class: |
B01D
53/08 (20060101); B01D 53/06 (20060101); B01D
53/50 (20060101); B01J 008/00 (); C01B 017/00 ();
C01B 021/02 (); C10G 011/02 () |
Field of
Search: |
;423/244A,244R,239,235,563,239A,573G,576 ;208/113,120 ;55/73 |
References Cited
[Referenced By]
U.S. Patent Documents
Primary Examiner: Heller; Gregory A.
Attorney, Agent or Firm: Tolpin; Thomas W. McClain; William
T. Magidson; William H.
Claims
What is claimed is:
1. A gas purification process, comprising the steps of:
withdrawing a particulate-laden gaseous stream comprising
particulates and sulfur oxides from a combustor of a processing
unit selected from the group consisting of a catalytic cracking
unit, a synthetic fuels plant, a coal liquefaction plant, a
gasification plant, a power plant, a paper mill, a steel mill, and
a waste treatment facility;
removing large gross particulates from said particulate-laden
gaseous stream in at least one cyclone by passing said
particulate-laden gaseous stream through at least one cyclone;
feeding said particulate-laden gaseous stream to a vessel after
said particulate-laden gaseous stream has been passed through at
least one cyclone, said vessel having a bed of sulfur
oxide-capturing and particulate-removing material comprising at
least one member selected from the group consisting of adsorbers
and adsorbers with at least one promoter thereon, said adsorbers
substantially comprising an oxide of at least one metal selected
from the group consisting of aluminum, bismuth, manganese, yttrium,
antimony, tin, a rare earth metal, a Group 1a metal, and a Group 2a
metal, and said promoter selected from the group consisting
essentially of a rare earth metal, a Group 8 metal, chromium,
vanadium, rhenium, and combinations thereof;
substantially decreasing the concentration of both particulates and
sulfur oxides in said particulate-laden gaseous stream in said
vessel; and
said decreasing comprising simultaneously removing a substantial
portion of said particulates and a substantial portion of said
sulfur oxides from said particulate-laden gaseous stream by passing
said particulate-laden gaseous stream through a portion of said bed
of sulfur oxide-capturing and particulate-removing material in said
vessel.
2. A gas purification process in accordance with claim 1 wherein
said gaseous stream further comprises nitrogen oxides from said
combustor and said decreasing includes decreasing the concentration
of nitrogen oxide in said gaseous stream by substantially removing
a substantial portion of said nitrogen oxides from said
particulate-laden gaseous stream in said vessel by passing said
gaseous stream through a portion of said bed.
3. A gas purification process in accordance with claim 1 wherein
said sulfur oxides and particulates are removed by chemical
adsorption in said vessel at a temperature ranging from about
1,200.degree. F. to about 1,400.degree. F. and spent adsorbers
containing said removed particulates and sulfur oxides are
regenerated with a reducing gas consisting essentially of hydrogen,
ammonia, carbon monoxide, light hydrocarbon gases, and combinations
thereof.
4. A gas purification process in accordance with claim 1 including
cracking oil in a catalytic cracking unit in the presence of a
cracking catalyst, regenerating said catalyst in a regenerator of
said catalytic cracking unit to emit an effluent stream laden with
combusted, spent cracking catalyst particulates and sulfur oxides,
said combustor comprising said regenerator and said
particulate-laden stream comprising said effluent stream.
5. A gas purification process in accordance with claim 1 including
processing synthetic fuel selected from the group consisting
essentially of oil shale, tar sands, coal, lignite, peat,
diatomite, uintaite, and biomass in a synthetic fuels plant to
liberate synthetic oil, said processing including emitting an
effluent stream laden with substantially combusted synthetic fuel
particulates and sulfur oxides, and said particulate-laden stream
comprises said effluent stream.
6. A gas purification process, comprising the steps of:
cracking a hydrocarbon feedstock in a reactor of a catalytic
cracking unit in the presence of a cracking catalyst under
catalytic cracking conditions to produce an upgraded cracked
product leaving spent cracking catalyst;
regenerating said spent cracking catalyst in a regenerator;
emitting regenerator particulate-laden off-gases comprising sulfur
oxides and cracking catalyst particulates from said
regenerator;
passing said regenerator off-gases generally downwardly through a
substantially vertical conduit of a granular bed filter and
scrubber, and thereafter, through at least a portion of a
downwardly moving bed of sulfur oxide-capturing and
particulate-removing material to remove a substantial portion of
said cracking catalyst particulates and sulfur oxides from said
gases so as to produce substantially purified gases having a
substantially lower concentration of sulfur oxides and cracking
catalyst particulates than said regenerator off-gases and leaving
spent sulfur oxide-capturing and particulate-removing material with
said cracking catalyst particulates and sulfur-containing deposits
thereon selected from the group consisting essentially of sulfur
oxides, sulfates, and combinations thereof;
removing said spent sulfur oxide-capturing and particulate-removing
material from said granular bed filter and scrubber and feeding
said removed material to a generally upright lift pipe riser having
an overhead collection vessel;
regenerating said spent sulfur oxide-capturing and
particulate-removing material in said lift pipe riser while
simultaneously moving said spent sulfur oxide-capturing and
particulate-removing material substantially upwardly in said lift
pipe riser to substantially remove said particulates and said
sulfur-containing deposits from said material while emitting
effluent gases containing said removed particulates and
sulfur-containing material selected from the group consisting of
hydrogen sulfide, sulfur-containing deposits, and combinations
thereof;
feeding said regenerated sulfur oxide-capturing and
particulate-removing material directly to said granular bed filter
and scrubber from said lift pipe riser for use as part of said
downwardly moving bed;
removing a substantial portion of said particulates from said
effluent gases in at least one cyclone;
recovering elemental sulfur from said effluent gases from said lift
pipe riser in a sulfur recovery unit;
said sulfur oxide-capturing said particulate-removing material
being selected from the group consisting essentially of adsorbers
and adsorbers with at least one promoter thereon, said absorbers
substantially comprising an oxide of at least one metal selected
from the group consisting of aluminum, bismuth, manganese, yttrium,
antimony, tin, a rare earth metal, a Group 1a metal, and a Group 2a
metal, and said promoter being selected from the group consisting
essentially of a rare earth metal, a Group 8 metal, chromium,
vanadium, rhenium, and combinations thereof; and
at least 90% by weight of said sulfur oxides in said regenerator
off-gases are removed by said bed.
7. A gas purification process in accordance with claim 6 wherein
said purified gases are withdrawn from said granular bed filter and
scrubber and fed to a turbine, said purified gases powering said
turbine, said turbine driving a blower, and said blower injecting
air into said regenerator to substantially combust said spent
cracking catalyst.
8. A gas purification process in accordance with claim 6 wherein
said regenerator has a dense phase bed in its lower portion and a
dilute phase bed in its upper portion and said regenerating
includes substantially complete burning of carbon monoxide in said
regenerator.
9. A gas purification process in accordance with claim 6 including
removing nitrogen oxides from said regenerator off-gases in said
granular bed filter and scrubber.
10. A gas purification process in accordance with claim 6 wherein
said regeneration of said spent sulfur oxide-capturing and
particulate-removing material in said lift pipe riser comprises
thermal regeneration with a supplemental fuel including at least
one member selected from the group consisting of torch oil,
hydrogen sulfide, and light hydrocarbon gases in said lift pipe
riser, and injecting said supplemental fuel into said lift pipe
riser.
11. A gas purification process in accordance with claim 6 wherein
said sulfur oxides are removed from said regenerator off-gases by
chemical adsorption at a temperature ranging from 1,200.degree. F.
to 1,400.degree. F. in said granular bed filter and scrubber, and
said regeneration of said spent sulfur oxide-capturing and
particulate-removing material comprises reacting said spent sulfur
oxide-capturing and particulate-removing material with a reducing
gas selected from the group consisting essentially of hydrogen,
ammonia, carbon monoxide, light hydrocarbon gases, and combinations
thereof, in said lift pipe riser.
12. A gas purification process in accordance with claim 11 wherein
said reacting includes converting said sulfur-containing deposits
in said lift pipe riser to hydrogen sulfide.
13. A gas purification process, comprising the steps of:
cracking a hydrocarbon feedstock in a reactor of a catalytic
cracking unit in the presence of a cracking catalyst under
catalytic cracking conditions to produce an upgraded cracked
product leaving spent cracking catalyst;
regenerating said spent cracking catalyst in a regenerator;
emitting regenerator particulate-laden off-gases comprising sulfur
oxides and cracking catalyst particulates from said
regenerator;
passing said regenerator off-gases generally downwardly through a
substantially vertical conduit of a granular bed filter and
scrubber, and thereafter, through at least a portion of a
downwardly moving bed of sulfur oxide-capturing and
particulate-removing material to remove a substantial portion of
said cracking catalyst particulates and sulfur oxides from said
gases so as to produce substantially purified gases having a
substantially lower concentration of sulfur oxides and cracking
catalyst particulates than said regenerator off-gases and leaving
spent sulfur oxide-capturing and particulate-removing material with
said cracking catalyst particulates and sulfur-containing deposits
thereon selected from the group consisting essentially of sulfur
oxides, sulfates, and combinations thereof;
removing said spent sulfur oxide-capturing and particulate-removing
material from said granular bed filter and scrubber and feeding
said removed material to a generally upright lift pipe riser having
an overhead collection vessel;
regenerating said spent sulfur oxide-capturing and
particulate-removing material in said lift-pipe riser while
simultaneously moving said spent sulfur oxide-capturing and
particulate-removing material substantially upwardly in said lift
pipe riser to substantially remove said particulates and said
sulfur-containing deposits from said material while emitting
effluent gases containing said removed particulates and
sulfur-containing material selected from the group consisting of
hydrogen sulfide, sulfur-containing deposits, and combinations
thereof;
feeding said regenerated sulfur oxide-capturing and
particulate-removing material directly to said granular bed filter
and scrubber from said lift pipe riser for use as part of said
downwardly moving bed;
removing a substantial portion of said particulates from said
effluent gases in at least one cyclone;
recovering elemental sulfur from said effluent gases from said lift
pipe riser in a sulfur recovery unit; and
said sulfur oxide-capturing and particulate-removing material
comprising alumina selected from the group consisting essentially
of gamma alumina, chi-eta-rho alumina, delta alumina, and theta
alumina.
14. A gas purification process in accordance with claim 13 wherein
said alumina contains 2 ppm to 6 ppm by weight promoter selected
from the group consisting essentially of platinum, ceria, and
combinations thereof.
15. A gas purification process, comprising the steps of:
cracking a hydrocarbon feedstock in a reactor of a catalytic
cracking unit in the presence of a cracking catalyst under
catalytic cracking conditions to produce an upgraded cracked
product leaving spent cracking catalyst;
regenerating said spent cracking catalyst in a regenerator;
emitting regenerator particulate-laden off-gases comprising sulfur
oxides and cracking catalyst particulates from said
regenerator;
passing said regenerator off-gases generally downwardly through a
substantially vertical conduit of a granular bed filter and
scrubber, and thereafter, through at least a portion of a
downwardly moving bed of sulfur oxide-capturing and
particulate-removing material to remove a substantial portion of
said cracking catalyst particulates and sulfur oxides from said
gases so as to produce substantially purified gases having a
substantially lower concentration of sulfur oxides and cracking
catalyst particulates than said regenerator off-gases and leaving
spent sulfur oxide-capturing and particulate-removing material with
said cracking catalyst particulates and sulfur-containing deposits
thereon selected from the group consisting essentially of sulfur
oxides, sulfates, and combinations thereof;
removing said spent sulfur oxide-capturing and particulate-removing
material from said granular bed filter and scrubber and feeding
said removed material to a generally upright lift pipe riser having
an overhead collection vessel;
regenerating said spent sulfur oxide-capturing and
particulate-removing material in said lift pipe riser while
simultaneously moving said spent sulfur oxide-capturing and
particulate-removing material substantially upwardly in said lift
pipe riser to substantially remove said particulates and said
sulfur-containing deposits from said material while emitting
effluent gases containing said removed particulates and
sulfur-containing material selected from the group consisting of
hydrogen sulfide, sulfur-containing deposits, and combinations
thereof;
feeding said regenerated sulfur oxide-capturing and
particulate-removing material directly to said granular bed filter
and scrubber from said lift pipe riser for use as part of said
downwardly moving bed;
removing a substantial portion of said particulates from said
effluent gases in at least one cyclone;
recovering elemental sulfur from said effluent gases from said lift
pipe riser in a sulfur recovery unit; and
said absorbers comprising magnesium aluminate spinels.
16. A gas purification process, comprising the steps of:
cracking a hydrocarbon feedstock in a reactor of a catalytic
cracking unit in the presence of a cracking catalyst under
catalytic cracking conditions to produce an upgraded cracked
product leaving spent cracking catalyst;
regenerating said spent cracking catalyst in a regenerator;
emitting regenerator particulate-laden off-gases comprising sulfur
oxides and cracking catalyst particulates from said
regenerator;
passing said regenerator off-gases generally downwardly through a
substantially vertical conduit of a granular bed filter and
scrubber, and thereafter, through at least a portion of a
downwardly moving bed of sulfur oxide-capturing and
particulate-removing material to remove a substantial portion of
said cracking catalyst particulates and sulfur oxides from said
gases so as to produce substantially purified gases having a
substantially lower concentration of sulfur oxides and cracking
catalyst particulates than said regenerator off-gases and leaving
spent sulfur oxide-capturing and particulate-removing material with
said cracking catalyst particulates and sulfur-containing deposits
thereon selected from the group consisting essentially of sulfur
oxides, sulfates, and combinations thereof;
removing said spent sulfur oxide-capturing and particulate-removing
material from said granular bed filter and scrubber and feeding
said removed material to a generally upright lift pipe riser having
an overhead collection vessel;
regenerating said spent sulfur oxide-capturing and
particulate-removing material in said lift pipe riser while
simultaneously moving said spent sulfur oxide-capturing and
particulate-removing material substantially upwardly in said lift
pipe riser to substantially remove said particulates and said
sulfur-containing deposits from said material while emitting
effluent gases containing said removed particulates and
sulfur-containing material selected from the group consisting of
hydrogen sulfide, sulfur-containing deposits, and combinations
thereof;
feeding said regenerated sulfur oxide-capturing and
particulate-removing material directly to said granular bed filter
and scrubber from said lift pipe riser for use as part of said
downwardly moving bed;
removing a substantial portion of said particulates from said
effluent gases in at least one cyclone;
recovering elemental sulfur from said effluent gases from said lift
pipe riser in a sulfur recovery unit; and
said sulfur oxide-capturing and particulate-removing material
comprising alumina and magnesia.
17. A gas purification process in accordance with claim 16 wherein
said alumina and magnesia material has at least one promoter
thereon ranging from 2 ppm to 6 ppm by weight selected from the
group consisting essentially of platinum, ceria, and combinations
thereof.
Description
BACKGROUND OF THE INVENTION
This invention relates to flue gas cleanup and, more particularly,
to removing sulfur oxides and particulates from a gaseous stream,
such as from a regenerator in a catalytic cracking unit.
Flue gases emitted in combustors, such as in regenerators and power
plants, often contain undesirable levels of sulfur oxides (SOx),
nitrogen oxides (NOx), and particulates which, if untreated, might
pollute the atmosphere.
Sulfur oxides in the presence of water can form sulfuric acid
causing acid rain. Nitrogen oxides may cause smog by photochemical
reaction with hydrocarbons in the atmosphere. Particulates in flue
gases typically include ash (soot) and/or spent combusted catalyst
with trace metals, such as arsenic and other contaminants which, in
excessive levels, could poison vegetation and livestock.
Over the years, various methods have been suggested for controlling
and/or removing sulfur oxide and/or nitrogen oxide emissions. In
catalytic cracking units, sulfur oxide control processes usually
occur in the regenerator. In one widely used process, sulfur oxides
are reacted in the regenerator in the presence of a catalyst to
form hydrogen sulfide which is withdrawn with the product stream
from the catalytic cracker and subsequently treated in a sulfur
recovery plant. Some of the methods suggested for removing nitrogen
oxides in regenerators, however, poison the cracking catalyst and
are, therefore, unacceptable. Typifying these prior art methods for
controlling sulfur oxide and/or nitrogen oxide emissions are those
described in U.S. Pat. Nos. 2,493,218; 2,493,911; 2,522,426;
2,575,520; 2,863,824; 2,992,895; 3,023,836; 3,068,627; 3,264,801;
3,501,897; 3,755,535; 3,760,565; 3,778,501; 3,832,445; 3,835,031;
3,840,643; 3,846,536; 3,892,677; 4,001,376; 4,006,066; 4,039,478;
4,153,534; 4,153,535; 4,181,705; 4,206,039; 4,218,344; 4,221,677;
4,233,276; 4,238,317; 4,241,033; 4,254,616; 4,258,020; 4,267,072;
4,300,997; 4,323,542; 4,325,811; 4,369,109; 4,369,130; 4,376,103;
4,381,991; 4,405,443; 4,423,019; and 4,443,419. These prior art
methods have met with varying degrees of success.
Flue gas streams discharged from regenerators, power plants, or
other combustors are commonly directed through one or more
dedusters, such as flue gas scrubbers, electrostatic precipitators,
cyclones, bag houses, granular bed filters, or other filters, in
order to remove particulates from the flue gas stream. Typifying
these dedusters and other prior art particulate-removing devices
are those shown in U.S. Pat. Nos. 3,540,388; 3,550,791; 3,596,614;
3,608,529; 3,608,660; 3,654,705; 3,672,341; 3,696,795; 3,741,890;
3,769,922; 3,818,846; 3,882,798; 3,892,658; 3,921,544; 3,922,975;
4,017,278; 4,126,435; 4,196,676; and 4,421,038. These dedusters and
prior art devices have met with varying degrees of success.
The combined use of flue gas scrubbers and electrostatic
precipitators, while often effective to control particulate
emissions, is very expensive and cumbersome.
It is therefore desirable to provide an improved process to remove
sulfur oxides and particulates from gaseous streams.
SUMMARY OF THE INVENTION
An improved process is provided for efficiently, effectively, and
economically removing sulfur oxides (SOx) and particulates from
gaseous streams, such as flue gases, to minimize emission of
pollution and contaminants into the atmosphere. The novel process
is particularly useful to clean up combustion off-gases emitted
from regenerators of catalytic cracking units to environmentally
acceptable levels. The process is also beneficial to effectively
remove sulfur oxides and particulates from combustion gases emitted
from synthetic fuel plants, such as those which retort, solvent
extract, or otherwise process oil shale, tar sands, diatomaceous
earth (diatomite), uintaite (gilsonite), lignite, peat, and
biomass, as well as to effectively remove sulfur oxides and
particulates emitted from coal liquefaction and gasification
plants. The disclosed process is also useful to clean up flue gases
from power plants, paper mills, steel mills, waste (garbage)
treatment sites, chimneys, smoke stacks, etc. The process is also
useful for removing nitrogen oxides (NOx) from gaseous streams.
To this end, sulfur oxide, nitrogen oxide, and particulate-laden
gases are treated and purified in a single processing vessel,
preferably a granular bed filter and scrubber, located downstream
of the combustor to remove simultaneously sulfur oxides, nitrogen
oxides, and particulates from the gases. In the processing vessel,
the particulates, nitrogen oxides, and sulfur oxides are
simultaneously removed from the dusty sulfur and nitrogen
oxide-containing gases by passing the gases through at least a
portion of a bed of sulfur oxide-capturing, nitrogen
oxide-capturing, and particulate-removing material. Desirably, the
gases are fed into the vessel and passed through the portion of the
bed at an angle of inclination from 30.degree. to 90.degree.
relative to the horizontal axis of the vessel and most preferably
vertically downwardly at right angles (perpendicular) to the
horizontal axis for best results.
Preferably, the bed of sulfur oxide-capturing, nitrogen
oxide-capturing, and particulate-removing material is a downwardly
moving bed of granular material in the form of balls, spheres,
pebbles, or pellets. The preferred granular material is alumina
adsorbers, although adsorbers comprising oxides of other metals can
also be used, either alone or in combination with alumina and/or
each other, such as bismuth, manganese, yttrium, antimony, tin,
rare earth metals, Group 1a metals, and/or Group 2a metals.
The adsorbers can be coated with a catalyst that promotes the
removal of sulfur oxides. While the preferred catalyst is platinum,
other catalytic metals, both free and in a combined form, can be
used, either alone or in combination with platinum and/or each
other, such as rare earth metals, Group 8 metals, chromium,
vanadium, rhenium, and combinations thereof.
The spent material (adsorbers) containing the captured particulates
and sulfur oxides can be regenerated, such as in a lift pipe riser
or transfer line, to remove the sulfur oxides and particulates from
the adsorbers. The regenerated adsorbers can be recycled to the
processing vessel, with or without additional scrubbing or
stripping, as desired. In one form, the adsorbers are regenerated
thermally, such as by combustion or other heating means. In another
form, the adsorbers are regenerated with a reducing gas to convert
the sulfur oxides to hydrogen sulfide. The reducing gas can be
hydrogen, ammonia, carbon monoxide, or light hydrocarbon gases,
such as methane, ethane, propane, etc. The reducing gas can also be
diluted with steam to attain a shift reaction or steam reforming in
order to produce hydrogen and carbon dioxide. Hydrogen produced in
this manner serves as a very effective and relatively inexpensive
reducing gas to convert sulfur oxides to hydrogen sulfides. The
hydrogen sulfide can be treated in a hydrogen sulfide treatment
plant, such as an amine recovery unit and a Claus plant. The
particulates in the dusty effluent gases can be removed downstream
of the regenerator in one or more filters, such as a cyclone and/or
bag house.
Particulates emitted from catalytic cracking units are mainly
combusted spent catalyst. Particulates emitted from synthetic fuel
plants are mainly combusted synthetic fuels (spent
hydrocarbon-containing material). Particulates emitted from power
plants, steel mills, waste treatment sites, etc., contain ash
and/or other material.
As used in this application, the terms "sulfur oxide" and "sulfur
oxides" mean sulfur dioxide and/or sulfur trioxide.
The term "SOx" as used herein means sulfur oxide.
The terms "nitrogen oxide" and "nitrogen oxides" as used herein
mean nitric oxide (NO) and/or nitrogen dioxide (NO.sub.2).
The term "NOx" as used herein means nitrogen oxide.
The terms "spend catalyst," "spent promoter," and "spent material"
as used herein mean a catalyst, promoter, or material,
respectively, which has been at least partially deactivated.
A more detailed explanation of the invention is provided in the
following description and appended claims taken in conjunction with
the accompanying drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a schematic flow diagram of a gas purification process in
accordance with principles of the present invention;
FIG. 2 is a schematic flow diagram of part of the gas purification
process with air, instead of a reduction gas, being injected into
the lift pipe riser;
FIG. 3 is a schematic flow diagram of an amine recovery unit;
FIG. 4 is a schematic flow diagram of a sulfur recovery unit;
and
FIG. 5 is a cross-sectional view of a catalytic cracking unit.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
Referring now to FIG. 1, a gas purification process 10 is provided
to remove sulfur oxides (SOx) and particulates from a gaseous
stream 12, such as flue gases, to minimize emission of pollution
and contaminants into the atmosphere. While the process of the
present invention is described hereinafter with particular
reference to cleanup of combustion off-gases emitted from the
regenerator 14 of a catalytic cracking unit 16, it will be apparent
that the process of the present invention can also be used to
effectively clean up combustion gases (flue gases) emitted from
other combustors, such as those from synthetic fuel plants, which
retort, solvent extract, or otherwise process oil shale, tar sands,
diatomaceous earth (diatomite), uintaite (gilsonite), lignite,
peat, and biomass, coal liquefaction and gasification plants, power
plants, paper mills, steel mills, waste (garbage) treatment sites,
chimneys, smoke stacks, etc.
In the gas purification process of FIG. 1, a hydrocarbon feedstock,
such as gas oil, is fed through feedstock line 18 into the bottom
of a catalytic cracking reactor 20, such as a fluid catalytic
cracker (FCC). Fresh make-up catalytic cracking catalyst and
regenerated catalytic cracking catalyst are fed into the reactor
through fresh make-up catalyst line 22 and regenerated catalyst
line 24, respectively. In the reactor, the hydrocarbon feedstock is
volatilized, gasified, and fluidized upon being mixed with the hot
cracking catalyst and the feedstock is catalytically cracked to
more valuable hydrocarbons. The catalytically cracked hydrocarbons
are withdrawn from the top of the reactor through overhead product
line 26 and conveyed to downstream processing equipment (not shown)
for further upgrading, separation into fractions, and/or further
processing.
Spent catalyst is discharged from the reactor through spent
catalyst line 28 and fed to the bottom portion of an upright,
fluidizable catalyst regenerator or combustor 14. The reactor and
regenerator together provide the primary components of the
catalytic cracking unit. Air is injected upwardly into the bottom
portion of the regenerator through air injector line 30 by air pump
32. The air is injected at a pressure and flow rate to fluidize,
propel, convey, and transport the spent catalyst particles
generally upwardly through the regenerator. Residual carbon (coke)
contained on the catalyst particles is substantially completely
combusted in the regenerator leaving regenerated catalyst for use
in the reactor. The regenerated catalyst is discharged from the
regenerator through regenerated catalyst line 24 and fed to the
reactor. The combustion off-gases (flue gases) are withdrawn from
the top of the combustor through an overhead combustion off-gas
line or flue gas line 12. The combustion off-gases or flue gases
contain minute particulates of combusted spent catalyst particles
as well as sulfur oxides (SOx) and nitrogen oxides (NOx). The
particulates in the combustion off-gases and flue gases emitted
from the regenerator of a catalytic cracking unit are very small
and typically range in size from 20 microns to less than 0.1
micron. Under present government environmental standards, the
particulates, SOx, and NOx in the flue gases are pollutants which
must be redued to environmentally acceptable levels before the flue
gases are vented to the atmosphere.
In the regenerator 33 of FIG. 5, the regenerator has a dense phase
lower section 34 and a dilute phase upper section 36 to provide for
substantially complete carbon monoxide (CO) burning and combustion
in the manner described by Horecky et al., U.S. Pat. No. 3,909,392,
which is hereby incorporated by reference in its entirety. The
regenerator can also have one or more internal cyclones 38 and 39
for removing some of the combusted particulates from combustion
gases. The removed catalyst particles are discharged through dip
legs or return lines 40 and 41 at the lower end of the cyclones
into the dense phase lower portion 34. The regenerator can also
have an eductor or eductor tube 42 to disperse the spent cracking
catalyst particles in a fountain, rain, or spouted bed into the
dilute phase upper portion of the regenerator, via valve 43, with
the aid of air, steam, or inert gases.
As shown in FIG. 5, the catalytic cracking reactor 43 (catalytic
cracker) can also have a dense phase lower portion 44 and a dilute
phase upper portion 46, as well as one or more internal cyclones 48
and 49 for removing cracking catalyst particles from the gaseous
product stream before the cracked product stream is removed from
the reactor. Downwardly depending dip legs or return lines 50 and
51 from the internal cyclones in the reactor return the cracking
catalyst particles to the lower portion of the reactor. If desired,
external cyclones can be used instead of internal cyclones.
The reactor 43 can also have a steam stripping section 52 at the
bottom of the reactor which is of a smaller cross-sectional area
than the outer walls of the dilute and dense phase portions of the
reactor. Steam is injected into the steam stripping portion 52
through steam line 54 to steam strip volatile hydrocarbons from the
cracking catalyst particles. The steam also serves to fluidize the
cracking catalyst in the stripping portion 52 as well as to
fluidize the cracking catalyst in the lower dense phase 44 of the
reactor. The steam stripping portion can have internals, such as
conical baffles 56 and donuts 57, to enhance flow and steam
stripping. A high temperature second stage steam stripper can also
be used.
The spent catalyst can be withdrawn from the bottom of the steam
stripper section through spent catalyst line 58, via control valve
59, instead of from the upper portion of the reactor, if desired,
and can be transported upwardly into the lower portion of the
regenerator 33 through a transfer line 60 and regenerator inlet
lines 61 and 62, via inlet valves 63 and 64, with the aid of air
from air injector 65. The regenerated catalyst can be withdrawn
from the bottom of the regenerator 33 through regenerated catalyst
lines 65 and 66, if desired, instead of from the upper portion of
the regenerator and conveyed by regenerated catalyst line 67, valve
68, and reactor inlet line 69 to the dilute phase portion 46 of the
reactor 43 along with the hydrocarbon feedstock from feedstock line
70. The temperature in the regenerator can be controlled by steam
pod injector 71.
Suitable hydrocarbon feedstocks for the catalytic cracking unit
preferably have a boiling point above the gasoline boiling range,
for example from about 400.degree. F. to about 1,200.degree. F.,
and are usually catalytically cracked at temperatures ranging from
about 850.degree. F. to about 1,200.degree. F. Such feedstocks can
include various mineral oil fractions boiling above the gasoline
range, such as light gas oils, heavy gas oils, wide-cut gas oils,
vacuum gas oils, kerosenes, decanted oils, residual fractions
(resid), reduced crude oils, and cycle oils derived from any of
these, as well as suitable fractions derived from shale oil, tar
sands oil, diatomaceous earth oil, coal liquefaction, or other
synthetic oils. Such fractions may be employed singly or in any
desired combination.
Catalytic cracking of heavy mineral oil fractions is an important
refining operation in the conversion of crude oils to desirable
fuel products, such as high-octane gasoline fuel used in
spark-ignited, internal combustion engines. In fluid catalytic
cracking, high molecular weight hydrocarbon liquids or vapors are
contacted with hot, finely-divided solid catalyst particles in a
fluidized bed reactor such as shown in FIG. 1 or in an elongated
riser reactor such as shown in FIG. 5, and the catalyst-hydrocarbon
mixtures are maintained at an elevated temperature in a fluidized
or dispersed state for a sufficient period of time to obtain the
desired degree of cracking to lower molecular weight hydrocarbons
typically present in motor gasoline and distillate fuels.
In usual cases where riser cracking is employed for conversion of a
gas oil, the throughput ratio, or volume of total feed to fresh
feed, may vary from about 1 to 3. The conversion level may vary
from about 40 to about 100 weight percent and advantageously is
maintained above about 60 weight percent, for example, between
about 60 and 90 weight percent. The term "conversion" is generally
used herein as the percentage reduction by weight of hydrocarbons
boiling above about 430.degree. F. at atmospheric pressure by the
formation of lighter materials or coke.
The weight ratio of total cracking catalyst-to-oil in the riser
reactor (catalytic cracker) can vary within the range of from about
2 to about 20 in order that the fluidized dispersion will have a
density within the range of from about 1 to about 20 pounds per
cubic foot. Desirably, the catalyst-to-oil ratio is maintained
within the range of from about 3 to about 20, preferably 3 to about
7 for best results. The fluidizing velocity in the riser reactor
(catalytic cracker) can range from about 10 to about 100 feet per
second. The riser reactor can have a ratio of length-to-average
diameter of about 25.
For production of a typical naphtha product, the bottom section
mixing temperature within the riser reactor (catalytic cracker)
above the stripping section is advantageously maintained at about
1,000.degree. F. to about 1,100.degree. F. for vaporization of the
oil feed so that the top section's product exit temperature will be
about 950.degree. F. For cracking resids and synthetic fuels,
substantially higher mixing temperatures in the bottom section of
the reactor, such as about 2,000.degree. F., may be necessary for
effective cracking.
Under the above conditions, including provision for a rapid
separation of spent catalyst from effluent oil vapor, a very short
period of contact between the cracking catalyst and oil will be
established. Contact time within the riser reactor (catalytic
cracker) will generally be within the range of from about 1 to
about 15 seconds, preferably within the range of from about 3 to
about 10 seconds. Short contact times are preferred because most of
the hydrocarbon cracking occurs during the initial increment of
contact time and undesirable secondary reactions are avoided. This
is especially important if higher product yield and selectivity,
including lesser coke production, are to be realized.
Short contact time between cracking catalyst particles and oil
vapors can be achieved by various means. For example, cracking
catalyst may be injected at one or more points along the length of
a lower, or bottom, section of the riser reactor (catalytic
cracker). Similarly, oil feed may be injected at all the points
along the length of the lower section of the riser reactor and a
different injection point may be employed for fresh and recycle
feed streams. Auxiliary nozzles can also be used to disperse resids
or other feedstock onto the catalyst for more efficient catalytic
cracking reactions. The lower section of the riser reactor above
the stripping section may, for this purpose, include up to about 80
percent of the total riser length in order to provide extremely
short effective contact times inducive to optimum conversion of
petroleum feeds. The reactor is preferably designed to minimize
cracking of the product in the dilute phase. Where a dense catalyst
bed is employed, provision may also be made for injection of
cracking catalyst particles and/or oil feed directly into the
dense-bed zone.
While the conversion conditions specified above are directed to the
production of gasoline as fuel for spark-ignition internal
combustion engines, the process may be suitably varied to permit
maximum production of heavier hydrocarbon products such as jet
fuel, diesel fuel, heating oil and chemicals and, in particular,
olefins and aromatics.
In catalytic cracking, some non-volatile carbonaceous material, or
"coke", is deposited on the catalyst particles. Coke comprises
highly condensed aromatic hydrocarbons which generally contain a
minor amount of hydrogen, such as from about 4 to about 10 weight
percent. When the hydrocarbon feedstock contains organic sulfur
compounds, the coke also contains sulfur and nitrogen. As coke
builds up on the catalyst, the activity of the catalyst for
cracking and the selectivity of the catalyst for producing gasoline
blending stocks diminish. The catalyst particles may recover a
major proportion of their original capabilities by removal of most
of the coke therefrom in the catalyst regenerator.
The spent catalyst from the petroleum conversion reaction in the
reactor is preferably stripped in the steam stripping section 52
(FIG. 5) prior to entering the regenerator. The stripping section
for use in the fluidized bed catalytic cracker may be maintained
essentially at a conversion reactor temperature in the range of
from about 200.degree. F. to about 1,200.degree. F. and preferably
above about 870.degree. F. for best results. The preferred
stripping gas is steam although steam containing a diluent, such as
nitrogen or some other inert gas or flue gas, may also be employed.
The stripping gas can be injected into the stripping section at a
pressure of at least about 10 psig, preferably about 35 psig, to
attain substantially complete removal of volatile compounds from
the spent conversion catalyst. If desired, an inert stripping gas
may be used instead of steam.
Catalyst regeneration is accomplished by burning the coke deposits
from the catalyst surface with a molecular oxygen-containing gas,
such as air. The oxidation of coke may be characterized in a
simplified manner as the oxidation of carbon as shown below.
Reactions (a) and (b) both can occur under typical catalyst
regeneration conditions with the catalyst temperature ranging from
about 1,050.degree. F. to about 1,450.degree. F. or higher and are
exemplary of gas-solid chemical interactions when regenerating
cracking catalyst at temperatures within this range. The effect of
any increase in temperature is reflected in an increased rate of
combustion of carbon and a more complete removal of carbon, or
coke, from the catalyst particles. As the increased rate of
combustion is accompanied by an increased evolution of heat
whenever sufficient free or molecular oxygen is present, the
gas-phase reaction (c) may occur. This latter reaction is initiated
and propagated by free radicals and can be catalyzed.
The burning of sulfur-containing and nitrogen-containing coke
deposits from the catalyst also results in the formation of sulfur
oxides and nitrogen oxides, and although the disclosed invention is
not to be limited thereby, sulfur-compound and sulfur oxide burning
may be represented by the following chemical equations:
Reactions (d) and (e) also occur under typical cracking catalyst
regeneration conditions. While reaction (d) is fast, reaction (e)
is relatively slow. Reaction (e) can be catalyzed by any catalyst
which catalyzes reaction (c) above.
Stripped deactivated cracking catalyst is regenerated by burning
the coke deposits from the catalyst surface with air or some other
combustion-sustaining molecular oxygen-containing regeneration gas
in a regenerator. This burning results in the formation of
combustion products such as sulfur oxides, carbon monoxide, carbon
dioxide, and steam. The oxygen-containing regeneration gas can
contain a diluent, such as nitrogen, steam, carbon dioxide,
recycled regenerator effluent gases, and the like. The molecular
oxygen concentration of the regeneration gas is ordinarily from
about 2 to about 30 volume percent and preferably from about 5 to
about 25 volume percent. Since air is conveniently employed as a
source of molecular oxygen, a major portion of the inert gas can be
nitrogen. The regeneration zone temperatures are ordinarily in the
range from about 1,049.degree. F. to about 1,454.degree. F. and are
preferably in the range from about 1,148.degree. F. to about
1,355.degree. F. Other regeneration temperatures may be used in
some circumstances. When air is used as the regeneration gas, it
can be injected into the bottom of the regenerator from a blower or
compressor at a fluidizing velocity in the range from about 0.15 to
about 5 feet per second and preferably from about 0.5 to about 3
feet per second.
Suitable cracking catalysts include those containing silica and/or
alumina, including the acidic type. The cracking catalyst may
contain other refractory metal oxides such as magnesia or zirconia.
Preferred cracking catalysts are those containing crystalline
aluminosilicates, zeolites, or molecular sieves, in an amount
sufficient to materially increase the cracking activity of the
catalyst, e.g., between about 1 and about 25% by weight. The
crystalline aluminosilicates can have silica-to-alumina mole ratios
of at least about 2:1, such as from about 2 to 12:1, preferably
about 4 to 6:1 for best results.
The crystalline aluminosilicates are usually available or made in
sodium form and this component can be reduced, for instance, to
less than about 4 or even less than about 1% by weight through
exchange with hydrogen ions, hydrogen-precursors such as ammonium
ions, or polyvalent metal ions. Suitable polyvalent metals include
calcium, strontium, barium, and the rare earths such as cerium,
lanthanum, neodymium, and naturally-occurring rare earths and their
mixtures. Such crystalline materials are able to maintain their
pore structure under the high temperature conditions of catalyst
manufacture, hydrocarbon processing and catalyst regeneration. The
crystalline aluminosilicates often have a uniform pore structure of
exceedingly small size with the cross-sectional diameter of the
pores being in a size range of about 6 to 20 angstroms, preferably
about 10 to 15 angstroms. Silica-based cracking catalysts having a
major proportion of silica, e.g., about 60 to 90 weight percent
silica and about 10 to 40 weight percent alumina, are suitable for
admixture with the crystalline aluminosilicate or for use as such
as the cracking catalyst. Other cracking catalysts and pore sizes
can be used.
The cracking catalyst particles are finely-divided and may have an
average particle size in the range of about 150 microns to about 20
microns or less.
The regeneration gas serving to fluidize the dense bed contains
free or molecular oxygen and the oxygen is preferably charged to
the regenerator in an amount somewhat in excess of that required
for complete combustion of coke (carbon and hydrogen) to carbon
dioxide and steam. The amount of oxygen in excess of that required
for complete combustion of the coke may vary from about 0.1 to
about 35 or more percent of the theoretical stoichiometric oxygen
requirement for complete combustion of the coke but,
advantageously, need not be greater than about 10 percent. For
example, when air is employed as the regeneration gas, a 10 percent
excess of air provides only about 2 volume percent oxygen in the
effluent spent gas stream. Advantageously, the concentration of
molecular or free oxygen and carbon monoxide at any point within
the regenerator is maintained outside of the explosive range at
those conditions to eliminate any risk of detonation.
An oxidation-promoting, carbon monoxide-burning catalyst can be fed
to the regenerator to promote complete burning of carbon monoxide
to carbon dioxide in the regenerator. The solid oxidation catalyst
can be in a finely-divided form, such as powder, separate from the
hydrocarbon cracking catalyst, or can be supported on another
substrate and admixed with the cracking catalyst. The support for
the oxidation catalyst can be less catalytically active, or even
inert, to the oxidation and hydrocarbon conversion reactions.
Desirably, the support is porous. The support can have a surface
area, including the area of the pores on the surface, of at least
about 10, preferably at least about 50, square meters per gram.
Illustrative of the supports, which may be essentially amorphous,
are silica, alumina, silicaalumina, and the like. Solid, platinum
group metal or rhenium oxidation catalysts may be used as can other
oxidation catalysts that promote the oxidation of carbon monoxide
in the presence of molecular oxygen. These oxidation catalysts
contain a catalytic metal which promotes the oxidation. The metal
may be in combined form, such as an oxide, rather than being in the
elemental state. The oxidation catalysts can be rhenium or a
platinum group metal of Group 8, such as platinum, palladium and
rhodium. The solid oxidation catalyst may comprise two or more
catalytically-active metals either physically or chemically
combined. By a chemical combination of metals, there are included
bi- or poly-metallic salts or oxides. Illustrative of combinations
of catalytically-active metals which may promote oxidation of
carbon monoxide without unduly adversely affecting the hydrocarbon
cracking operations are combinations of the platinum group metals,
e.g., platinum, rhenium, the oxides of iron and rhenium, and the
like. Other metals can be used.
The substrate for the solid oxidation-promoting carbon
monoxide-burning catalyst may be a portion of the cracking catalyst
or may be different therefrom, for example, it may be a
non-catalytic, porous, solid substrate. When the hydrocarbon
cracking catalyst serves as the substrate, care should be taken in
selection of the deposition process such that the cracking activity
and selectivity of the catalyst is not adversely affected. It is
preferred that if the hydrocarbon cracking catalyst is of the type
having ion-exchanged sites, the ion-exchange be completed prior to
deposition of the oxidation catalyst. The amount of
oxidation-promoting metal employed for promotion of the oxidation
of carbon monoxide may be in a minor amount effective to enhance
the desired oxidation. This amount may be very small, e.g., as
little as about 0.01 part per million or less based on the weight
of the hydrocarbon cracking catalyst employed. The amount of
oxidation-promoting metal may often be at least about 0.1 ppm up to
about 5 or about 10 ppm. Larger amounts of the oxidation-promoting
metal, such as about 0.01 to 5, or about 0.05 to 1, percent by
weight based on the hydrocarbon cracking catalyst, may be
employed.
In order to remove sulfur oxides and particulates from the
regenerator/combustion off-gases (flue gases), the sulfur oxide and
particulate-laden gases are passed through a granular bed filter
and scrubber 80 (FIG. 1), either directly or indirectly, after
passing through one or more cyclones to remove some of the large
gross particulates. The granular bed filter and scrubber is an
elongated, upright single, sulfur oxide-capturing and
particulate-removing vessel which filters particulates and scrubs
sulfur oxides from the influent flue gases. The granular bed filter
and scrubber has an exterior vertical sidewall 82 with a circular
cross-section, an elongated frustro-conical bottom section or
portion 84 whose flared sidewalls converge downwardly and terminate
into an outlet or discharge mouth 86 along the vertical axis of the
granular bed filter and scrubber, and an upwardly converging roof
or top 88.
The granular bed filter and scrubber has a vertical conduit or pipe
90 which provides a gas inlet line. The conduit extends vertically
downwardly through the roof along the vertical axis of the filter
and scrubber to a discharge position in the upper portion of the
interior of the frustro-conical bottom section. The vertical
conduit has an enlarged head 92 at its upstream end which extends
upwardly through the roof, an elongated main body 94 which has a
smaller cross-section than the head and is circumferentially
surrounded by the sidewall 82, and has an outwardly flared
discharge portion 96 at its downstream end with downwardly
converging frustro-conical walls which terminate in a gas outlet
and discharge mouth 98. The upstream head of the conduit preferably
has a vertical inlet mouth 100, although in some circumstances it
may be desirable to have a horizontal inlet mouth.
Extending downwardly from the roof within the interior of the
filter and scrubber is an annular frustro-conical, adsorber
collection reservoir or ball hopper 102 whose flared sidewalls
converge downwardly and surround the upper portion of the vertical
conduit. Discharge chutes or outlet pipes 104 and 106 extend
generally downwardly from the reservoir into or slightly above a
downwardly-moving bed 108 of sulfur oxide-capturing and
particulate-removing material. The chutes can include a
centrally-disposed vertical discharge chute 104 that
circumferentially and concentrically surrounds a portion of the
main body section 94 of the vertical conduit and symmetrical,
outwardly inclined, angular chutes 106 which extend downwardly and
outwardly at an angle of inclination relative to the vertical axis
of the filter and scrubber. Extending outwardly from the sides of
the filter and scrubber is a gas outlet line 110. A regenerated
adsorber-inlet line 114 extends generally downwardly at an angle of
inclination through the roof of the scrubber and filter.
In the preferred embodiment, the bottom frustro-conical section 84
of the granular bed filter and scrubber is filled with a downwardly
moving bed 108 of sulfur oxide-capturing and particulate-removing
granular material which is in the form of balls, pebbles, spheres,
or pellets. The sulfur oxide-capturing and particulate-removing
material provides adsorbers or acceptors which adsorb, collect,
and/or otherwise remove sulfur oxides and particulates from the
influent gaseous stream (regenerator flue gases). In the most
preferred embodiment, the bed of granular material is a bed of
sulfur oxide and nitrogen oxide-capturing and particulate-removing
material, which serve as sulfur dioxide, nitrogen oxide, and
particulate adsorbers or acceptors. The adsorbers enter the
granular bed filter and scrubber through fresh make-up adsorber
line 112 or regenerated adsorber line 114 and descend by gravity
into the frustro-conical adsorber reservoir 102. The adsorbers are
discharged downwardly from the reservoir through the downwardly
extending chutes into the downwardly moving bed.
The adsorbers preferably comprise substantially alumina, and most
preferably alumina compounded with magnesia, for best results.
Gamma (.gamma.) alumina, chi-eta-rho (.chi., .eta., .rho.)alumina,
delta (.delta.) alumina, and theta (.theta.) alumina are
particularly useful as adsorbers and supports because of their high
surface areas. While alpha (.alpha.) alumina and beta (.beta.)
alumina can be used as adsorbers, they are not as effective as
gamma, chi-eta-rho, delta, and theta alumina. The oxides of other
metals can also be used as adsorbers, either alone or in
combination with alumina, or as spinels, such as bismuth,
manganese, yttrium, antimony, Group 1a metals, Group 2a metals,
rare earth metals, and combinations thereof. Magnesium aluminate
spinels are particularly useful as adsorbers. Lanthanum and cerium
are preferred rare earth metals. Naturally occurring rare earths,
such as in the form of baestanite, are also useful adsorbers. The
adsorbers can also be a blend/mixture of high density and low
density materials, such as of the above-identifield metal
oxides.
The adsorbers can be impregnated or otherwise coated with a
catalyst or promoter that promotes the removal of sulfur oxides.
The preferred catalyst is ceria (cerium oxide) and most preferably
platinum for best results. Other catalytic metals, both free and in
a combined form, can be used, either alone or in combination with
each other and/or in combination with ceria and/or alumina, such as
rare earth metals, Group 8 metals, chromium, vanadium, rhenium, and
combinations thereof. The promoter can comprise the same material
as the adsorber. An even uniform distribution of the promoter is
preferred for best results and to minimize adsorber erosion.
The Group 1a metals, Group 2a metals, and Group 8 metals referred
to are those listed in the Periodic Table of the Elements in the
Handbook of Chemistry and Physics (54th Edition). Useful Group 1a
metals include: lithium, sodium, potassium, rubidium, and cesium.
Useful Group 2a metals include magnesium, calcium, strontium, and
barium. Useful Group 8 metals are the Group 8 noble metals (the
palladium family of metals) including ruthenium, rhodium,
palladium, osmium, iridium, and platinum. The rare earth metals are
also referred to as lanthanides. Useful rare earth metals include
cerium, praseodymium, neodymium, promethium, samarium, europium,
gadolinium, terbium, dysprosium, holmium, erbium, thulium,
ytterbium, and lutetium.
In operation, the regenerator off-gases (flue gases) in gas line 12
pass into vertical conduit 90 and flow vertically downwardly along
and about the vertical axis of the granular bed filter and scrubber
until being discharged from the mouth 98 of the conduit into the
bed of sulfur oxide-capturing and particulate-removing material
(adsorbers). Depending on the velocity and pressure of the flue
gases, the gaseous stream (flue gases) will pass downwardly through
a portion of the bed before circulating upwardly. The adsorbers
serve to scrub, filter, adsorb, or otherwise remove the
particulates and sulfur oxides (SOx) from the flue gases. The
cleansed, purified flue gases are withdrawn from the granular bed
filter and scrubber through the inlet mouth of the gas outlet line
110, located above the bed, where the purified gases can be safely
vented to the atmosphere or conveyed, expanded, fed, and used to
drive and propel the turbine blades of a power recovery turbine 116
or other equipment. The turbine can be connected to drive the air
blower or pump 32.
In use, the granular bed filter has a highly concentrated
collection zone at the exit (mouth) of the vertical conduit where
downwardly flowing flue gas enters the bed of adsorbers, along with
a downstream counterflow collection region which substantially
assures that cleansed (purified) flue gas always exits upwardly
through the downwardly moving bed of adsorbers.
The amount of sulfur dioxide (SO.sub.2) adsorbed on a platinum
catalyst/promoter, such as a 2 ppm platinum catalyst on an alumina
adsorber, depends on the amount of catalyst used (space velocity)
as well as the temperature at which the adsorption is done. The
amount of sulfur dioxide adsorbed, measured as breakthrough time,
is greatest at either low temperatures of about 500.degree. F. or
high temperatures of about 1,200.degree. F. to about 1,400.degree.
F. Sulfur dioxide adsorption will occur at intermediate
temperatures ranging from 800.degree. F. to 1,100.degree. F. at an
acceptable, but lesser, efficiency. Some sulfur dioxide adsorption
may occur at a temperature as low as 200.degree. F. and as high as
1,600.degree. F. in the granular bed filter and scrubber.
The spent adsorbers containing or coated with the removed
particulates and sulfur oxides and/or sulfates are discharged
through spent adsorber outlet 86 and conveyed by gravity flow
through spent adsorber line 118 to the bottom of a spent adsorber
regenerator comprising a lift pipe riser 120 or transfer line. The
spent absorbers can be continuously discharged from the bottom of
the granular bed filter and scrubber and conveyed to the
regenerator lift pipe where they are regenerated, scrubbed, and/or
cleansed before being recycled back to the granular bed filter and
scrubber. To this end, a reducing gas (reduction gas) such as
hydrogen, ammonia, carbon monoxide, or light hydrocarbon gases,
such as methane, is injected upwardly into the lift pipe riser by
gas injector 122. The reducing gas can also be diluted with steam
to attain a shift reaction or steam reforming in order to produce
hydrogen and carbon monoxide. The steam can be injected into the
lift pipe riser (1) along and as part of the reducing gas or (2)
through a separate steam injector 123. The reducing gas is injected
upwardly at a sufficient velocity and pressure to propel, carry,
transport, and convey the adsorbers upwardly through the lift pipe
riser into an overhead collection vessel 124. In the lift pipe
riser, the reducing gas reacts with the spent adsorbers and
simultaneously removes the particulates and sulfur oxides (SOx)
while converting the sulfur oxides to hydrogen sulfide (H.sub.2 S).
Hydrogen produced by a steam shift reaction or steam reforming
serves as an effective and relatively inexpensive reducing gas to
convert sulfur oxides to hydrogen sulfides. The regenerated,
cleansed adsorbers are recycled and conveyed from the overhead by
gravity through regenerated adsorber line 114 into the granular bed
filter and scrubber. Excess regenerated adsorbers can be removed
from the system through overflow line 126 and discarded or stored
in a hopper.
Methane can be an even more economical reductant or reducing gas
under certain conditions than hydrogen. When using methane in the
lift pipe riser, the reduction duration influences the sulfur
dioxide (SO.sub.2) pick-up capacity (regeneration) of the spent
alumina adsorbers. At a reduction temperature of 1,200.degree. F.
in the lift pipe riser, relatively short methane contact times of
about 5 seconds are more effective towards restoring sulfur dioxide
(SO.sub.2) pick-up capacity (regeneration) of alumina adsorbers
circulated in the granular bed filter and adsorber at a
1,300.degree. F. adsorption temperature than longer methane contact
times of from 30 to 45 seconds. When the reduction temperature in
the lift pipe riser is increased to at least 1,300.degree. F., the
effect of methane contact time duration is negligible.
Desirably, the reducing gas also strips, scrubs, or otherwise
removes the captured nitrogen oxides (NOx) from the adsorbers in
the lift pipe riser and simultaneously converts the removed
nitrogen oxides (NOx) to water or steam and molecular nitrogen
(N.sub.2) which can be safely vented to the atmosphere from the
overhead collection vessel through the outlet gas line.
The effluent spent reducing gas, which contains hydrogen sulfide
and the removed particulates, is withdrawn from the overhead vessel
124 through gas outlet line 128 where it is passed through one or
more cyclones 130 in order to remove most of the particulates via
particulate discharge line 132. The filtered gases exit the cyclone
through gas line 134 where they can be fed to a bag house 136 to
remove most of the remaining particulates through particulate line
138. The filtered gases exit the bag house through gas line 140
where they are passed to an amine recovery unit 142 to concentrate
the hydrogen sulfide. Hydrogen sulfide from the vapor recovery and
upgrading unit (not shown) downstream of the catalytic cracker, can
also be fed to the amine recovery unit. The concentrated hydrogen
sulfide is passed from the amine recovery unit through concentrated
hydrogen sulfide line 144 to a sulfur recovery unit 146, such as a
Claus plant, to recover elemental sulfur through sulfur recovery
line 148. The recovered sulfur can be safely stacked in piles or
transported elsewhere for other uses. If the level of hydrogen
sulfide (H.sub.2 S) in the filtered spent reducing gas in line 140
is sufficiently concentrated, the filtered gases can be sent
directly to the sulfur recovery unit 146 via bypass line 150,
bypassing the amine recovery unit.
In the preferred embodiment, in order to effectively and
efficiently remove the particulates and sulfur oxides (SOx) from
the regenerator/combustion off-gases (flue gases), the off-gases
should enter the granular bed filter and scrubber at a temperature
ranging from 200.degree. F. to 1,800.degree. F. and most preferably
from 500.degree. F. to 1,400.degree. F., at a pressure from
atmospheric pressure to 500 psia. For best results, the granular
bed filter and scrubber should be operated at a temperature ranging
from 200.degree. F. to 1,600.degree. F., preferably from
1,000.degree. F. to 1,400.degree. F., and most preferably from
about 1,300.degree. F. to about 1,350.degree. F. at a pressure from
14 psia to 300 psia and preferably from atmospheric pressure to 150
psia. The maximum design operating temperature of the granular bed
filter is 2,000.degree. F. The granular bed filter and scrubber has
an efficiency ranging from 85% to 100% and preferably greater than
95%.
The solids flux flow rate of the adsorbers fed into the granular
bed filter and scrubber is from 10 to 2,000 lbs/ft.sup.2 hr, and
preferably between 20 and 200 lbs/ft.sup.2 hr for best results. The
regenerated and fresh adsorbers are fed into the granular bed
filter at a temperature ranging from 200.degree. F. to
1,800.degree. F. and preferably from 500.degree. F. to
1,400.degree. F., at a pressure ranging from 15 to 300 psia and
preferably from atmospheric pressure to 150 psia. The adsorbers
range in diameter (size) from 1 mm to 13 mm and preferably from 2
mm to 5 mm for best results. Adsorbers ranging in size from 2 to 5
mm are not only effective in removing particulates but provide
excess capacity to adsorb sulfur oxides (SOx) and therefore provide
a comfortable margin of safety to minimize downtime resulting from
attrition or replacement of adsorbers. Only a small fraction of
alumina adsorbers, typically less than 1% by weight, is utilized
for sulfur dioxide (SO.sub.2) capture. The low utilization of the
alumina adsorbers avoids the problem of alumina integrity.
Integrity problems arise when about 30% or more of the alumina
adsorbers are used for sulfur dioxide (SO.sub.2) capture in large
amounts of steam.
The feed ratio (space velocity) of the sulfur oxide-removing
catalyst/promoter per lbs/min sulfur dioxide (SO.sub.2) in the
regenerator off-gases (flue gases) per lb of adsorber is from
1.times.10.sup.-3 to about 1.times.10.sup.-5 and most preferably
from about 2.times.10.sup.-4 to about 4.times.10.sup.-5 for best
results. The ratio of catalyst/promoter to adsorbers by weight is
in the range of 1.times.10.sup.-6 :1 to about 1:3 and most
preferably from about 2.times.10.sup.-6 :1 to about 1:9 for
enhanced results.
The adsorbers can have a crush strength ranging from 1 to 10 lbs/mm
and preferably between 2 and 8 lbs/mm. The attrition weight of the
regenerated adsorbers being recycled through the granular bed
filter can range from 0.1% to 2% and is preferably less than 1% per
day for less downtime. The surface area-to-weight ratio of the
adsorbers can range from 5 to 400 m.sup.2 /g unsteamed, and 2 to
250 m.sup.2 /g if steamed during pretreatment. The pore volume of
the adsorbers can range from 0.3 to 1.5 m.sup.2 /g unsteamed, and
preferably from 0.25 to 1 m.sup.2 /g if steamed during
pretreatment. The pore radius of the adsorbers can range from 30 to
90 .ANG. unsteamed, and preferably from 50 to 200 .ANG. if steamed
during pretreatment.
The bulk density of the moving bed of adsorbers can range from 20
to 120 lbs/ft.sup.3 and preferably about 40 lbs/ft.sup.3. The bed
of adsorbers moves downwardly on the order of 1 to 30 in/hr and
preferably from about 2 to 20 in/hr. The flue gas residence time in
the bed of adsorbers can range from 1 to 10 seconds and preferably
is about 2 seconds with a superficial flue gas velocity through the
bed ranging from 0.5 to 5 ft/sec and preferably from about 1 to 2
ft/sec.
The solids residence time of the particulates as well as the
adsorbers in the granular bed filter and scrubber is from 1 to 10
hours and preferably from 2 to 4 hours for greater efficiency. The
gas residence time of the flue gases in the granular bed filter and
adsorber is from 1 to 5 seconds and preferably from 2 to 4 seconds
for greater effectiveness.
The lift pipe riser/adsorber-regenerator is preferably operated at
a temperature of 1,000.degree. F. to 1,600.degree. F. and
preferably from 1,200.degree. F. to 1,400.degree. F., at a total
pressure ranging from 15 to 300 psia and preferably from
atmospheric pressure to 150 psia, at a hydrogen partial pressure
ranging from 0.1p to 1p and preferably from at least 0.5p for best
results. The solids residence time of the particulates as well as
the adsorbers in the lift pipe riser can be from 15 seconds to 10
minutes, preferably from 60 seconds to 150 seconds and the gas
residence time in the lift pipe riser can be from 10 to 30 seconds,
preferably from 16 to 18 seconds for best results. The spent
adsorbers are heated in the lift pipe riser to a temperature
ranging from 800.degree. F. to 1,600.degree. F. and preferably from
1,200.degree. F. to 1,400.degree. F. for best results. The lift gas
velocity in the lift pipe riser can range from 5 to 100 ft/sec and
preferably from about 20 to 40 ft/sec for best results.
The conversion level of removing particulates from the flue gas
stream in the granular bed filter and scrubber is from 85% to 100%
and preferably at least 95% for best results. The conversion level
of removing sulfur oxides (SOx) from flue gases in the granular bed
filter and scrubber is from 85% to 100% and preferably at least 95%
for best results. The conversion level of removing nitrogen oxides
(NOx) from flue gases in the granular bed filter and scrubber is
from 85% to 100% and preferably at least 95% for best results.
The conversion level of removing particulates from the spent
adsorbers in the lift pipe riser is from 90% to 100% and preferably
from 95% to 98% for better efficiency. The conversion level of
converting sulfur oxides and/or sulfates to hydrogen (H.sub.2 S)
sulfide in the lift pipe riser is from 80% to 100% and preferably
greater than 99% for greater efficiency.
While the above operating conditions are preferred for best
results, in some circustances it may be desirable to use other
operating conditions. Furthermore, while the described granular bed
filter and scrubber is preferred to most effectively remove
particulates, sulfur oxides, and nitrogen oxides from flue gases,
in some circumstances it may be desirable to use other types of
vessels, devices, or apparatus to simultaneously remove
particulates, sulfur oxides, and nitrogen oxides from flue gases,
such as those shown in U.S. Pat. Nos. 4,017,278; 4,126,435; and
4,421,038, which are hereby incorporated by reference in their
entirety.
The sulfur oxide-capturing catalyst/promoter can be impregnated,
deposited, or sprayed onto the adsorbers or fed separately with the
adsorbers into the granular bed filter and scrubber.
EXAMPLE 1
A sulfur dioxide (SO.sub.2) adsorption capacity test was conducted
with flue gas having an inlet composition of 1,000 ppmv sulfur
dioxide, 3% by volume molecular oxygen (O.sub.2), and 2% by volume
water vapor with a gas flow rate of about 10 cc/min at a
temperature of 1,200.degree. F. Alumina adsorbers were used having
a crush strength of 7.47 lbs/mm, an attrition rate of 0.06%, an
unsteamed surface area of 198 m.sup.2 /g, a pore volume of 0.3609
cc/g unsteamed, and a pore radius of 32 .ANG. unsteamed. The
alumina adsorbers removed 204 .mu.l of sulfur dioxide (SO.sub.2)
per 50 mg of adsorbers.
EXAMPLE 2
A sulfur dioxide adsorption capacity test was conducted under the
same conditions as in Example 1, except that the alumina adsorbers
had a crush strength of 1.75 lbs/mm, an attrition rate of 0.01%, a
surface area of 269 m.sup.2 /g unsteamed, a pore volume of 0.8426
cc/g unsteamed, and a pore radius of 38 .ANG. unsteamed. The
adsorbers removed 241 .mu.l of sulfur dioxide (SO.sub.2) per 50 mg
of adsorbers.
EXAMPLE 3
A sulfur dioxide adsorption capacity test was conducted under the
conditions of Example 1, except that the alumina adsorbers were
impregnated with 2 ppm platinum catalyst/promoter to promote the
adsorption of SOx. The platinum-promoted alumina adsorbed 270 .mu.l
sulfur dioxide (SO.sub.2) per 50 mg of adsorbers.
EXAMPLE 4
A sulfur dioxide adsorption capacity test was conducted under the
conditions of Example 2, except that the alumina adsorbers were
impregnated with 2 ppm platinum. The platinum-promoted alumina
adsorbers removed 393 .mu.l of sulfur dioxide (SO.sub.2) per 50 mg
of adsorbers.
EXAMPLE 5
A sulfur dioxide adsorption capacity test was conducted under the
conditions of Example 1, except that the alumina adsorbers were
impregnated with 6 ppm platinum. The platinum-promoted alumina
adsorbers removed 324 .mu.l sulfur dioxide (SO.sub.2) per 50 mg of
adsorbers.
EXAMPLE 6
A sulfur dioxide adsorption capacity test was conducted under the
conditions of Example 2, except that the alumina adsorbers were
impregnated with 6 ppm platinum. The platinum-promoted alumina
adsorbers removed 414 .mu.l of sulfur dioxide (SO.sub.2) per 50 mg
of adsorbers.
EXAMPLE 7
A regeneration test was conducted to regenerate the spent
platinum-promoted alumina adsorbers of Example 4, while
simultaneously removing the captured sulfur oxide (SOx) and/or
sulfate from the adsorbers. The spent adsorbers were exposed to a
pure dry hydrogen stream flowing at 10 cc/min for about 30 seconds
at a temperature of 1,200.degree. F. The promoter was then
subjected to an air purge to oxidize the platinum sulfide to
platinum. The regenerated adsorbers were then used to adsorb the
sulfur dioxide (SO.sub.2) in the flue gas of Example 4 and achieved
virtually a 100% sulfur dioxide (SO.sub.2) removal rate in less
than 10 seconds.
EXAMPLE 8
A sulfur dioxide adsorption test was conducted on the flue gas of
Example 1 but at a temperature of 1,382.degree. F. and using
adsorbers comprising 100 mole percent magnesium (MgO) impregnated
with 6% by wt ceria (CeO.sub.2). After 92 min., 26,300 .mu.l of
sulfur dioxide (SO.sub.2) per 50 mg of adsorbers were adsorbed. The
adsorbers had an activity of 0.748 relative to the alumina
adsorbers impregnated with ceria.
EXAMPLE 9
A sulfur dioxide adsorption test was conducted under the conditions
of Example 8, except that the ceria-impregnated adsorbers contained
92.6 mole percent magnesium and 7.4 mole percent alumina. The
adsorbers removed 16,700 .mu.l of sulfur dioxide (SO.sub.2) per 50
mg of adsorbers and had a relative activity of 0.475.
EXAMPLE 10
A sulfur dioxide adsorption test was conducted under the conditions
of Example 8, except that the ceria-impregnated adsorbers contained
18.5 mole percent magnesia and 8.5 mole percent alumina. The
adsorbers removed 10,550 .mu.l of sulfur dioxide (SO.sub.2) per 50
mg of adsorbers and had a relative activity of 0.3.
EXAMPLE 11
A sulfur dioxide adsorption test was conducted under the conditions
of Example 8, except that the ceria-impregnated adsorbers contained
55.8 mole percent magnesia and 44.2 mole percent alumina. The
adsorbers removed 4,100 .mu.l of sulfur dioxide (SO.sub.2) per 50
mg of adsorbers and had a relative activity of 0.0117.
EXAMPLE 12
A sulfur dioxide adsorption test was conducted under the conditions
of Example 8, except that the ceria-impregnated adsorbers contained
33.5 mole percent magnesia and 66.5 mole percent alumina. The
adsorbers removed 1,700 .mu.l of sulfur dioxide (SO.sub.2) per 50
mg of adsorbers and had a relative activity of 0.048.
EXAMPLE 13
A sulfur dioxide adsorption test was conducted under the conditions
of Example 8, except that alumina adsorbers impregnated with 6% by
weight ceria were used. The adsorbers removed 650 .mu.l of sulfur
dioxide (SO.sub.2) per 50 mg of adsorbers and had a relative
activity of 0.018. The liquid hourly space velocity was 9,600
SCFH.
EXAMPLE 14
An attrition rate test was conducted with the adsorbers in Example
13. The adsorbers were found to have an attrition rate of
20.5%.
EXAMPLE 15
An attrition rate test was conducted with adsorbers comprising 16.7
mole percent magnesia and 83.3 mole percent alumina impreganted
with 6 weight percent ceria. The adsorbers were found to have an
attrition rate of 15.8%.
EXAMPLE 16
An attrition rate test was conducted with adsorbers comprising 15
mole percent magnesia and 50 mole percent alumina impregnated with
6 weight percent ceria. The attrition rate was found to be
9.7%.
EXAMPLE 17
An attrition rate test was conducted with adsorbers containing 83.3
mole percent magnesia and 16.7 mole percent alumina. The attrition
rate was found to be 7.0%
In the process of FIG. 1, the sulfur oxides (SOx) and particulates
are at least partially removed by chemical adsorption, sometimes
referred to as oxidative adsorption, with the captured SOx being
converted to hydrogen sulfide (H.sub.2 S) when reacted with a
reducing gas in the regenerator/lift pipe riser.
Captured sulfur dioxide (SO.sub.2) reacts with alumina adsorbers to
form alumina sulfate on the alumina adsorbers in accordance with
the following formula:
The efficiency of chemical adsorption (oxidative adsorption) in
removing sulfur dioxide (SO.sub.2) from the flue gases in the
granular bed filter and scrubber is enhanced if the operating
temperature of the granular bed filter and scrubber is in the range
of 1,200.degree. F. to 1,400.degree. F.
The spent adsorbers containing the alumina sulfate are regenerated
in the lift pipe riser by reacting the spent adsorbers with a
reducing gas, such as hydrogen, ammonia, carbon monoxide, or light
hydrocarbon gases, such as methane, to remove and convert the
alumina sulfate to hydrogen sulfide (H.sub.2 S). The regeneration
of the adsorbers and the removal of the captured sulfur dioxide in
the lift pipe riser is sometimes referred to as desorption.
The process of FIG. 2 is similar to the process of FIG. 1, except
that the adsorbers remove the sulfur oxides (SOx) and particulates
from the flue gas streams in the granular bed filter and scrubber
primarily by physical adsorption, sometimes referred to as
non-oxidative adsorption, and the spent adsorbers are thermally
regenerated in the lift pipe riser 120 by heat, preferably by
combustion with an oxygen-containing combustion-sustaining gas,
such as air, instead of a reducing gas, to remove the captured
sulfur oxides (SOx) and particulates from the spent adsorbers. The
additional heat which is required for thermal regeneration can be
supplied by combusting a fuel while in contact with the spent
adsorbers. The fuel can be injected into the lower portion of the
lift pipe riser through an auxiliary or supplemental fuel line 150.
The fuel can be torch oil, hydrogen sulfide, or light hydrocarbon
gases, such as methane. Other fuels can be used. Air is injected
upwardly into the lift pipe riser through air injector line 152 at
a sufficient pressure and velocity to convey, propel, carry, and
transport the adsorbers along with the particulates and sulfur
oxides to the overhead collection vessel 124. During thermal
regeneration, the particulates are removed (freed) from the
adsorbers, the captured sulfur oxides are removed and become more
concentrated, and/or the sulfates are removed from the adsorbers
and converted to sulfur dioxide (SO.sub.2). The effluent gases
containing the concentrated levels of sulfur dioxide (SO.sub.2),
and sometimes hydrogen sulfide (H.sub.2 S) from the combusted
auxiliary fuel in the overhead collection vessel are withdrawn from
the vessel by gas line 128 and fed to a sulfur recovery unit, such
as a Claus plant to recover elemental sulfur.
Adsorption efficiency, as measured by breakthrough times, for
removing sulfur dioxide (SO.sub.2) by physical adsorption
(non-oxidative adsorption) is enhanced if the granular bed filter
and scrubber is operated at a temperature ranging from 500.degree.
F. to 800.degree. F. The adsorption process for physically
adsorbing sulfur dioxide on alumina adsorbers can be characterized
by the following formula:
The hydrogen sulfide (H.sub.2 S) in the waste gases in the effluent
line 128 (FIG. 1) of the overhead collection vessel 124 can be
removed and concentrated by various methods, such as in an amine
recovery unit 142 with either diethanolamine (DEA) or
monoethanolamine (MEA), the iron sponge process, or the hot
potassium carbonate process. A DEA-operating amine unit is
preferred because it is more efficient and has less chemical
degradation and lower make-up risk than the other processes.
The amine recovery unit preferably decreases the concentration of
hydrogen sulfide in the waste gas stream to less than 1 part per
cubic foot of gas. DEA is preferred over MEA because of degradation
of MEA by carbonyl sulfide and carbon disulfide in the gases. DEA
amine solutions will absorb both hydrogen sulfide (H.sub.2 S) and
carbon dioxide (CO.sub.2) according to the following reaction:
##STR1## Absorption of hydrogen sulfide occurs in the amine
recovery unit at 100.degree. F. or below and rejection of sulfide
is active at 240.degree. F. The amine desulfurization process which
occurs in the amine recovery unit involves contacting the sour
sulfur-containing gas stream (waste gases) with a cool DEA amine
solution to absorb the hydrogen sulfide and then regenerate the
amine and strip the hydrogen sulfide from the amine solution by
heating.
In the preferred embodiment, the amine recovery unit takes the form
shown in FIG. 3, although other types of amine recovery units can
be used, if desired. In the embodiment of FIG. 3, sour waste gases
(acid gases) in waste gas line 140 are fed to an inlet scrubber 200
which removes (scrubs) entrained liquids, including distillate and
water, from the waste gases. The scrubbed gases are discharged from
the inlet scrubber through scrubber discharge line 202 and fed to
the bottom portion of a contactor or absorber column 204. A DEA
amine feed is pumped into the top portion of the absorber column by
amine charge pump 206 via amine feed line 208. In the adsorber
column, the scrubbed waste gases are contacted in countercurrent
flow relationship with the amine feed to react the hydrogen sulfide
and the carbon dioxide in the waste gases with the amine. The
adsorber column can be a trayed or packed tower and provides
gas-liquid adsorption.
Rich amine is discharged from the bottom of the adsorber column
through rich amine line 210 and fed to a flash tank 212 where it is
flashed at a reduced pressure to remove entrained gases through
entrained gas line 214. The flashed rich amine gases are discharged
from the bottom of the flash tank through discharge line 216 and
fed to and filtered in a carbon filter 218. The filtered rich amine
is fed through filtered amine line 220 to a rich/lean amine heat
exchanger 222 where the rich amine is heated. The heated rich amine
is discharged from the heat exchanger through heated rich amine
line 224 and fed to the upper portion of a stripper column, steam
stripper, or still 226.
Steam is injected into the lower portion of the steam stripper 226
through steam injection line 228. In the steam stripper, the rich
amine solution is regenerated and stripped of acid gases by the
steam. The concentrated acid gases are withdrawn from the steam
stripper through overhead acid gas line 230 and cooled in a water
cooler or condenser 232. The cooled acid gases are passed through
cooled acid gas line 234 and collected in a reflux accumulator 236.
Part of the concentrated acid gases in the reflux accumulator can
be recycled, refluxed, and pumped into the upper portion of the
steam stripper (stripper column) 226 by reflux pump 238 via reflux
lines 240 and 242. The excess acid gases can be discharged from the
reflux accumulator through excess gas line 244 and flared or sent
to a sulfur recovery unit, such as a Claus plant.
The stripped rich amine is discharged from the bottom of the steam
stripper 226 through stripped amine line 246 and fed to a reboiler
248. Steam is boiled out of the amine in the reboiler and withdrawn
through overhead steam line 228 where it is injected into the lower
portion of the steam stripper 226. The residual boiled lean amine
is discharged from the reboiler through lean amine discharge line
250 and passed through lean amine line 252 to heat exchanger 222.
The inventory of the lean amine in amine line 252 is controlled by
surge tank 254.
Lean amine exits the heat exchanger 222 through outlet line 256 and
is pumped through line 258 to a cooler or heat exchanger 260 by
booster pump 262. The lean amine solution is cooled in the heat
exchanger 260. The cooled amine is discharged from the heat
exchanger 260 through cooled amine line 264 and pumped through lean
amine feed line 208 into the upper portion of the absorber column
204 by amine charge pump 206.
Effluent gases are withdrawn from the absorber column through
overhead gas line 266 and fed to an outlet scrubber 268. The outlet
scrubber scrubs the gases from the gas line 266 to recover any
residual amine solution carried over in the effluent gases. The
sweet scrubber gases are discharged from the outlet scrubber throgh
sweet gas line 270.
The acid waste gases in lines 140 and 150 (FIG. 1), as well as the
acid gases in acid gas line 244 from the reflux accumulator 236,
are fed to a sulfur recovery unit and scavenger plant, preferably a
Claus plant, such as the type shown in FIG. 4. The Claus plant can
recover 99.0% or more of the elemental sulfur in the influent acid
gases.
As shown in FIG. 4, acid gases enter an oxidation unit and
waste-heat boiler 300 through an acid gas inlet line 302. In the
oxidation unit, about one-third of the hydrogen sulfide (H.sub.2 S)
in the acid gases is oxidized to sulfur dioxide (SO.sub.2) and
water or steam in accordance with the following exothermic
reaction:
The reaction furnace section 306 of the unit 300 is downstream of
the burner and provides a thermal region in which about 70% by
weight of the hydrogen sulfide (H.sub.2 S) of the remaining acid
gases and the sulfur dioxide (SO.sub.2) is converted to elemental
molecular sulfur and water or steam in accordance with the
following endothermic reaction:
Water is fed into the boiler section 308 of the unit 300 through
water line 310. The hot reaction gases in the reaction furnace,
which can be at a temperature such as 2,300.degree. F., are cooled
by the water in the water pipes of the boiler section to a much
cooler temperature, such as 1,100.degree. F. The water in the water
pipes of the boiler section is boiled and heated by the hot
reaction gases and converted to steam. Steam is removed from the
boiler section through steam line 312. In the boiler section, the
elemental sulfur is converted to S.sub.6 and S.sub.8 in accordance
with the following exothermic reactions:
and
Hot gases containing S.sub.6 and S.sub.8 are withdrawn from the
unit through gas bypass line 314.
The partially stripped reaction gases are removed from the unit 300
through outlet gas line 316. The stripped reaction gases typically
contain hydrogen sulfide (H.sub.2 S), sulfur dioxide (SO.sub.2),
elemental sulfur (S.sub.2), nitrogen (N.sub.2), carbonyl sulfide
(COS), carbon disulfide (CS.sub.2), and steam. The stripped
reaction gases can be withdrawn from the unit through gas line 316
at a temperature ranging from 550.degree. F. to 600.degree. F. The
stripped reaction gases in the gas line 316 are fed to a heat
exchanger 318 to cool the reaction gases to about 530.degree. F.
and condense or precipitate some of the sulfur. The condensed or
precipitated sulfur is removed from the heat exchanger through
sulfur line 320.
The cooled reaction gases are withdrawn from the heat exchanger 318
through cooled gas line 322 and fed to a first Claus converter 324.
The bottom portion of the converter contains a fixed catalyst bed
326 of sulfur-capturing catalysts. The reaction gases are passed
through the fixed catalyst bed in the first converter to
catalytically react the remaining hydrogen sulfide (H.sub.2 S) with
the sulfur dioxide (SO.sub.2) to form water and free sulfur. The
products are heated by the catalytic reaction to over 650.degree.
F. The reaction products are discharged from the first converter
through discharge line 328 and cooled in a cooler or heat exchanger
330 to condense, precipitate, and/or recover more sulfur. The
sulfur is removed from the heat exchanger through sulfur recovery
line 332.
The cooled reaction gases, which can be cooled to below 400.degree.
F., are withdrawn from the heat exchanger 330 through cooled
reaction gas line 334 and fed to a second Claus converter 336. The
second Claus converter also has a fixed catalyst bed 338 of
elemental sulfur-capturing catalyst. The reaction products are
passed through the catalyst bed 338 to catalytically react the
remaining hydrogen sulfide (H.sub.2 S) with the sulfur dioxide
(SO.sub.2) to form water and free sulfur. The resulting reaction
products are heated to a temperature slightly below 500.degree. F.
by the reaction in the second converter. The reaction products are
discharged from the second converter through reaction product
outlet line 330 and cooled in a cooler or heat exchanger 340 to
condense, precipitate, and/or remove substantially all of the
remaining sulfur.
The sulfur is removed from the heat exchanger 340 through sulfur
recovery line 342. The cooled tail gases are withdrawn from the
heat exchanger 340 through tail gas outlet line 344 and passed to
tail gas clean-up equipment 346, such as Beavon and Stretford
processing equipment, to clean up the tail gases. The sweet
cleansed tail gases are withdrawn from the tail gas clean-up
equipment through sweet gas line 348. Sulfur recovered from the
tail gases are removed from the tail gas clean-up equipment through
sulfur recovery line 350.
While the above two-stage Claus plant is preferred because it
recovers at least 95% elemental sulfur, other types of Claus plants
can be used, if desired, such as a split-stream Claus plant, a
partial-oxidation Claus plant, an ultra three-stage Claus plant,
etc.
Although embodiments of this invention have been shown and
described, it is to be understood that various modifications and
substitutions, as well as rearrangements and combinations of parts,
components, equipment, and/or process steps, can be made by those
skilled in the art without departing from the novel spirit and
scope of this invention.
* * * * *